1. Field of the Invention
This invention relates to the field of drilling wellbores and more specifically to the field of using drilling fluids at elevated temperatures to increase fracture gradients in a wellbore.
2. Background of the Invention
In the drilling industry, a drilling fluid is typically used when drilling a wellbore. The drilling fluid may be used to provide pressure in the wellbore, clean the wellbore, cool and lubricate the drill bit, and the like. The wellbore may comprise a cased portion and an open portion. The open portion extends below the last casing string, which may be cemented to the formation above a casing shoe. In standard operations, the drilling fluid is circulated into the wellbore through the drill string. The drilling fluid returns to the surface through the annulus between the wellbore wall and the drill string. The pressure of the drilling fluid flowing through the annulus acts on the open wellbore. The drilling fluid flowing up through the annulus carries with it cuttings from the wellbore and any formation fluids that may enter the wellbore.
The drilling fluid may be used to provide sufficient hydrostatic pressure in the well to prevent the influx of such formation fluids. Typically, the density of the drilling fluid is controlled in order to provide the desired downhole pressure. The formation fluids within the formation provide a pore pressure, which is the pressure in the formation pore space. When the pore pressure exceeds the pressure in the open wellbore, the formation fluids tend to flow from the formation into the open wellbore. Therefore, the pressure in the open wellbore is typically maintained at a higher pressure than the pore pressure. The influx of formation fluids into the wellbore is called a kick. Because the formation fluid entering the wellbore ordinarily has a lower density than the drilling fluid, a kick may potentially reduce the hydrostatic pressure within the wellbore and thereby allow an accelerating influx of formation fluid. If not properly controlled, this influx may lead to a blowout of the well. Therefore, the formation pore pressure typically comprises the lower limit for allowable wellbore pressure in the open wellbore, i.e. uncased borehole.
While it is highly advantageous to maintain the wellbore pressures above the pore pressure, if the wellbore pressure exceeds the formation fracture pressure, a formation fracture may occur. With a formation fracture, the drilling fluid in the annulus may flow into the fracture, decreasing the amount of drilling fluid in the wellbore. In some cases, the loss of drilling fluid may cause the hydrostatic pressure in the wellbore to decrease, which may in turn allow formation fluids to enter the wellbore. Therefore, the formation fracture pressure typically defines an upper limit for allowable wellbore pressure in an open wellbore. Typically, the formation immediately below the casing shoe will have the lowest fracture pressure in the open wellbore. Consequently, such fracture pressure immediately below the casing shoe is often used to determine the maximum annulus pressure. However, in other instances, the lowest fracture pressure in the open wellbore occurs at a lower depth in the open wellbore than the formation immediately below this casing shoe. In such an instance, pressure at this lower depth may be used to determine the maximum annulus pressure.
Pore pressure gradients and fracture pressure gradients as well as pressure gradients for the drilling fluid have been used to determine setting depths for casing strings to avoid pressures falling outside of the pressure limits in the wellbore. These pressure gradients represent a plurality of respective pore, fracture, and drilling fluid pressures versus depth in the wellbore. Typically, the fracture pressure is determined by performing a leak-off test below a casing shoe by applying surface pressure to the hydrostatic pressure in the wellbore. The fracture pressure is the point where a formation fracture initiates as indicated by comparing changes in pressure versus volume during the leak-off test. Typically, a leak-off test is performed immediately after circulating the drilling fluid. The circulating temperature is the temperature of the circulating drilling fluid, and the static temperature is the temperature of the formation.
Typically, circulating temperatures are lower than static temperatures. A fracture pressure determined from a leak-off test performed when circulating temperatures just prior to performing the test are less than static temperature is lower than a fracture pressure if the test were performed at static temperature. This is due to the changes in near wellbore formation stress resulting from the lower circulating temperature as compared to the higher static temperature. Similarly, for a circulating temperature higher than static temperature, the fracture pressure determined from a leak-off test would be higher than if the test would be performed at static temperature.
For any given open hole interval, the range of allowable fluid pressures lies between the pore pressure gradient and the fracture pressure gradient for that portion of the open wellbore between the deepest casing shoe and the bottom of the well. The pressure gradients of the drilling fluid may depend, in part, upon whether the drilling fluid is circulated, which will impart a dynamic pressure, or not circulated, which may impart a static pressure. Typically, the dynamic pressure comprises a higher pressure than the static pressure. Thus, the maximum dynamic pressure allowable tends to be limited by the fracture pressure. A casing string must be set or fluid density reduced when the dynamic pressure exceeds the fracture pressure if fracturing of the well is to be avoided. Since the fracture pressure is likely to be lowest at the highest uncased point in the well, the fluid pressure at this point is particularly relevant. In some instances, the fracture pressure is lowest at lower points in the well. For instance, depleted zones below the last casing string may have the lowest fracture pressure. In such instances, the fluid pressure at the depleted zone is particularly relevant.
When drilling a well, the depth of the initial casing strings and the corresponding casing shoes may be determined by the formation strata, government regulations, pressure gradient profiles and the like. The initial casing strings may comprise conductor casings, surface casings, and the like. The fracture pressures may limit the depth of the casing strings to be set below the casing shoe of the first initial casing string. These casing strings below the initial casing strings are intermediate casing strings and the like. To determine the maximum depth of the first intermediate casing string, a maximum initial drilling fluid density may be initially chosen with the circulating drilling fluid temperature lower than static temperature, which provides a dynamic pressure that does not exceed the fracture pressure at the first casing shoe. The maximum drilling fluid density may also be used to compare the static and/or dynamic pressure gradient to the pore pressure and fracture pressure gradients to indicate an allowable pressure range and a depth at which the casing string should be set. After the first intermediate casing string is set, the maximum density of the drilling fluid can be increased to a pressure at which the dynamic pressure does not exceed the fracture pressure at the casing shoe of the newly set casing string. Such new maximum drilling fluid density may then be used to again compare the static and/or dynamic pressure gradient to the pore pressure and fracture pressure gradients to indicate an allowable pressure range and a depth at which the next casing string should be set. Such procedures are followed until the desired wellbore depth is reached. Drawbacks to this technique using circulating drilling fluid temperatures lower than static temperature include the fact that a large number of casing strings are required to be set in the wellbore. The number of casing strings tends to increase the cost of drilling the well. In addition, the diameter of the wellbore is reduced with each successive casing string. Such reduction in size limits the size of the equipment that can be passed through the casing string.
Consequently, there is a need to safely and efficiently use fewer casing strings when drilling a well. Further, there is a need to increase the fracture pressure gradients. Additional needs comprise using increased fracture pressure gradients to increase the intervals between casing strings and limiting the loss of drilling fluids to the formation.